Supporting document for the Nordic Capacity Calculation Region’s proposal for capacity calculation methodology in accordance with Article 20(2) of Commission Regulation (EU)
2015/1222 of 24 July 2015
establishing a guideline on capacity allocation and congestion
management
Table of content:
1 Introduction and executive summary ... 6 Proposal for the Capacity Calculation Methodology ... 6 1.1
Capacity calculation process ... 7 1.2
2 Legal requirements and their interpretation ... 9 3 Introduction to FB capacity calculation methodology ... 20 Motivation behind introducing FB approach in the CCR Nordic ... 20 3.1
Description of FB approach ... 24 3.2
4 Motivation for the articles in the CCM proposal ... 31 Article 2: Definitions and interpretation ... 31 4.1
Article 3: Methodology for determining reliability margin (RM) ... 33 4.2
Article 4: Methodology for determining operational security limits ... 40 4.3
Article 5: Methodology for determining contingencies relevant to capacity calculation ... 42 4.4
Article 6: Methodology for determining allocation constraints ... 43 4.5
Article 7: Methodology for determining generation shift keys (GSK) ... 44 4.6
Article 8: Rules for avoiding undue discrimination between internal and cross-zonal exchanges 4.7
47
Article 9: Methodology for determining remedial actions (RAs) to be considered in capacity 4.8
calculation ... 52 Article 10: Mathematical description of the applied capacity calculation approach with
4.9
different capacity calculation inputs ... 55 Article 11: Impact of remedial actions (RAs) on CNEs ... 56 4.10
Article 12: Rules on the adjustment of power flows on critical network elements or of cross- 4.11
zonal capacity due to remedial actions ... 59 Article 13: Rules for taking into account previously allocated cross-zonal capacity ... 59 4.12
Article 14: A mathematical description of the calculation of power transfer distribution factors 4.13
(PTDFs) for the FB approach ... 59 Article 15: A mathematical description of RAMs on CNEs for the FB approach ... 61 4.14
Article 16: Rules for sharing the power flow capabilities of CNEs among different CCRs ... 61 4.15
Article 17: Methodology for the validation of cross-zonal capacity ... 61 4.16
Article 18: Target capacity calculation approach ... 63 4.17
Article 19: Mathematical description of the applied capacity calculation approach with 4.18
different capacity calculation inputs ... 63 Article 20: Rules for taking into account previously allocated cross-zonal capacity ... 64 4.19
Article 21: Rules on the adjustment of power flows on CNEs or of cross-zonal capacity due to 4.20
RAs 64
Article 22: A mathematical description of the calculation of PTDFs for the FB approach ... 64 4.21
Article 23: A mathematical description of RAMs on CNEs for the FB approach ... 64 4.22
Article 24: Rules for calculating cross-zonal capacity, including the rules for efficiently sharing 4.23
the power flow capabilities of CNEs among different bidding zone borders for the CNTC approach .... 64 Article 25: Rules for sharing the power flow capabilities of CNEs among different CCRs ... 67 4.24
Article 26: Methodology for the validation of cross-zonal capacity ... 67 4.25
Article 27: Reassessment frequency of cross-zonal capacity for the intraday timeframe ... 67 4.26
Article 28: Fallback procedure for the case where the initial capacity calculation does not lead 4.27
to any results ... 68 Article 29: Monitoring data to the national regulatory authorities ... 68 4.28
Article 30: Publication of data ... 68 4.29
Article 31: Capacity calculation process ... 69 4.30
Article 32: Publication and Implementation ... 69 4.31
5 Impact assessment ... 71 Quantitative impact assessment ... 71 5.1
Qualitative impact assessment ... 100 5.2
Cost of implementation and operation ... 121 5.3
Impact assessment in accordance with CACM article 3 ... 123 5.4
6 Timescale for the CCM implementation ... 126 Timeline for implementation of the CCM ... 126 6.1
7 ANNEX I: Example calculation of nodal PTDFs ... 127 8 ANNEX II: Model set-up for the Case study NO3-NO5 ... 129 9 ANNEX III: Detailed mathematical descriptions of power flow equations ... 132
Abbreviations:
AHC Advanced hybrid coupling
CCC Coordinated capacity calculator
CCM Capacity calculation methodology
CCR Capacity calculation region
CGM Common grid model
CNE Critical network element
CNTC Coordinated net transmission capacity
FAV Final adjustment value
FB Flow-based
FCR Frequency containment reserve
aFRR Automatic frequency restoration reserve
mFRR Manual frequency restoration reserve
Fmax Maximum flow on a CNE
Fref Flow on a CNE in the base case
Fref' Flow on a CNE at zero net position
FRM Flow reliability margin
GSK Generation shift key
IGM Individual grid model
MCO Market coupling operator
NEMO Nominated electricity market operator
NTC Net transfer capacity
PTDF Power transfer distribution factor
PTR Physical transmission right
RA Remedial action
RAM Remaining available margin
RM Reliability margin
RSC Regional security coordinator
SHC Standard hybrid coupling
TRM Transmission reliability margin
TSO Transmission system operator
Legal documents:
CACM Regulation Commission regulation (EU) 2015/1222 of 24 July 2015 establishing a guideline on capacity allocation and congestion management Guideline FCA Regulation Commission regulation (EU) 2016/1719 of 26 September 2016 establishing
a guideline on forward capacity allocation
SO Regulation Commission Regulation (EU) 2017/1485 of 2 August 2017 establishing a guideline on electricity transmission system operation
Balancing Regulation Commission Regulation (EU) 2017/2195 of 23 November 2017 establishing a guideline on electricity balancing
Regulation (EC) 714/2009 Regulation (EC) 714/2009 of the European Parliament and of the Council of 13 July 2009 on conditions for access to the network for cross-border exchanges in electricity and repealing Regulation (EC) no 1228/2003 Transparency Regulation Commission Regulation (EU) No 543/2013 of 14 June 2013 on submission
and publication of data in electricity markets and amending Annex I to Regulation (EC) No 714/2009 of the European Parliament and of the Council
1 Introduction and executive summary
This document is the supporting document for the Nordic Capacity Calculation Methodology (CCM). The document describes the CCM proposal for the day-ahead and intraday market timeframe for the Nordic Capacity Calculation Region (CCR), and provides an impact assessment of the proposed methodology.
The intention of this document is to provide explanation, background, and motivation on the proposed legal text on CCM.
On 17 September 2017, the Transmission System Operators (TSOs) of the CCR Nordic1 and the Norwegian TSO submitted after consultation with stakeholders a common proposal for the CCM in accordance with Article 20 of the Commission Regulation (EU) 2015/1222 establishing a guideline on capacity calculation and congestion management (CACM Regulation) to the Regulatory Authorities (NRAs) of the CCR Nordic2 and the Norwegian Regulatory Authority3.
According to Article 9 (7) (e) of the CACM GL, the proposal is subject to approval by all the NRAs of CCR Nordic4.
On 16 March 2018 the Nordic NRAs requested the Nordic TSOs to submit an amended proposal.
The amended proposal dated 16 May 2018 reflects the request for amendments received from NRAs.
Proposal for the Capacity Calculation Methodology
1.1With regard to the CACM Regulation Article 20(2), the Nordic TSOs are proposing to introduce a new CCM for the day-ahead and intraday market timeframes. In accordance to CACM Regulation Article 20(1), the capacity calculation approach for the day-ahead and intraday market timeframe shall be a flow-based (FB) approach unless the requirements in CACM Regulation Article 20(7) are met.
The CACM Regulation article 20(7) states that the TSOs may jointly apply for a coordinated net transmission capacity (CNTC) approach if the TSOs concerned are able to demonstrate that the application of the CCM using the FB approach would not yet be more efficient compared to the CNTC approach and assuming the same level of operational security in the concerned region.
1Svenska kraftnät, Fingrid, and Energinet.
2 The Swedish Energy Markets Inspectorate (Ei), The Danish Energy Regulatory Authority (DERA) and The Finnish Energy Authority (EV).
3 The Norwegian Water Resources and Energy Directorate (NVE).
4 Until Regulation 2015/1222 applies in Norway, NVE and Statnett are not formally part of the process. NVE, will however follow the process and may approve the proposed CCM from Statnett according to national legislation.
Proposed approaches for the day-ahead and intraday market timeframes
For the day-ahead market timeframe: The Nordic TSOs propose to implement a FB approach for the day-ahead market timeframe.
For the intraday market timeframe: As the long-term solution, the Nordic TSOs proposes to implement a FB approach for the intraday timeframe as soon as the intraday market platform is technically able to utilize FB parameters.
As an interim solution, the Nordic TSOs propose to implement a CNTC approach for the intraday market timeframe.
The current Nordic TSO proposal is based on preliminary quantitative and qualitative assessments, which has provided no evidence to support a hypothesis of the CNTC approach being as efficient as the FB approach. The assessment has been based on a comparison between FB and the current net transmission capacity (NTC) approach, where the current approach serves as a proxy for a CNTC approach. A prerequisite for implementing a FB approach for day-ahead market timeframe in the Nordics, is that the European day-ahead market platform is technically able to manage FB parameters.
The long term solution for the intraday market is proposed to be a FB approach. This approach cannot be implemented until the intraday market platform is technically able to utilize FB parameters. As an
interim solution, the Nordic TSOs propose to implement a CNTC approach in the intraday market timeframe until the FB approach becomes technically feasible.
The Nordic TSOs acknowledge that further work is needed to implement all features in capacity calculation required by CACM Regulation; to apply proper Common Grid Models (CGM) in calculations, to make the CCM robust and reliable before go-live, and to confirm that the implemented CCM approach can deliver results in line with the preliminary quantitative assessments, showing benefits of the CCM approach. During this process, the transparency towards stakeholder will be ensured.
Capacity calculation process
1.2The day-ahead and intraday electricity markets facilitate efficient matching of consumers and producers of electrical power. The sites of production and consumption of electric power are often located far apart, and the transfer of power between the two occurs through the electric transmission grid. Thus, the relevant physical limitations in the electricity grid must be calculated, simplified and communicated to the electricity market in order to maintain operational security. This is known as the capacity
calculation process. The capacity calculation process has to be distinguished from the capacity allocation process, which takes place for e.g. day-ahead at the power exchanges. The result of the capacity
calculation process is to be used as an input to the capacity allocation process. This document is a
detailed proposal covering the capacity calculation process. How this process relates to the adjacent processes before ending up with an actual allocation of capacity, is described in this section.
The capacity calculation process will be coordinated among TSOs. This means that individual grid models (IGMs) prepared by each TSO will be merged into a single European grid model. This Common Grid Model (CGM) will include relevant parts of European grids with forecasted production and consumption patterns for each market time unit. For the day-ahead timeframe this currently implies 24 scenarios, where the capacities will be defined. Capacities will be calculated at the CCR level by applying the CGM.
Each TSO will validate the results of the capacity calculation before the capacities are sent to the day- ahead and intraday market platforms. Figure 1 shows this coordinated capacity calculation process.
Figure 1 Coordinated capacity calculation process
Figure 1 illustrates whether the respective actions are performed on a TSO, a CCR region, or an European level. The actions requiring the most coordination and harmonization are the building of the CGM followed by the actual capacity calculation and the allocation. Capacity calculation shall be done on a CCR level.
IGMs are built on a TSO level using grid information, and input from market participants. Furthermore, the validation of capacity calculation results is performed at the TSO level, as the TSOs are the
responsible parties for network security and can best assess the quality and correctness of the capacity calculation results and they are liable for the power system operation.
2 Legal requirements and their interpretation
This chapter contains a description of the relevant legal references in CACM Regulation including some interpretative guidance.
The legal framework also needs to be interpreted in order to formulate a legally sound proposal on the CCM, to define the scope of this proposal, and to make the proposal implementable.
A number of relevant passages of the preamble of the CACM Regulation are cited, that should be taken into account to properly interpret the articles stated further below:
“(4) To implement single day-ahead and intraday coupling, the available cross-border capacity needs to be calculated in a coordinated manner by the Transmission System Operators
(hereinafter ‘TSOs’). For this purpose, they should establish a common grid model including estimates on generation, load and network status for each hour. The available capacity should normally be calculated according to the so-called flow-based calculation method, a method that takes into account that electricity can flow via different paths and optimises the available capacity in highly interdependent grids. The available cross-border capacity should be one of the key inputs into the further calculation process, in which all Union bids and offers, collected by power exchanges, are matched, taking into account available cross-border capacity in an economically optimal manner. Single day-ahead and intraday coupling ensures that power usually flows from low-price to high-price areas.
(6) Capacity calculation for the day-ahead and intraday market time-frames should be coordinated at least at regional level to ensure that capacity calculation is reliable and that optimal capacity is made available to the market. Common regional capacity calculation methodologies should be established to define inputs, calculation approach and validation requirements. Information on available capacity should be updated in a timely manner based on latest information through an efficient capacity calculation process.
(7) There are two permissible approaches when calculating cross-zonal capacity: flow-based or based on coordinated net transmission capacity. The flow-based approach should be used as a primary approach for day-ahead and intraday capacity calculation where cross-zonal capacity between bidding zones is highly interdependent. The flow-based approach should only be introduced after market participants have been consulted and given sufficient preparation time to allow for a smooth transition. The coordinated net transmission capacity approach should only be applied in regions where cross-zonal capacity is less interdependent and it can be shown that the flow-based approach would not bring added value.”
The most important definitions for the CCM, extracted from Article 2 of the CACM Regulation, are as follows:
“6. ‘allocation constraints’ means the constraints to be respected during capacity allocation to maintain the transmission system within operational security limits and have not been translated into cross-zonal capacity or that are needed to increase the efficiency of capacity allocation;
7. ‘operational security limits’ means the acceptable operating boundaries for secure grid operation such as thermal limits, voltage limits, short-circuit current limits, frequency and dynamic stability limits;
8. ‘coordinated net transmission capacity approach’ means the capacity calculation method based on the principle of assessing and defining ex ante a maximum energy exchange between adjacent bidding zones;
9. ‘flow-based approach’ means a capacity calculation method in which energy exchanges between bidding zones are limited by power transfer distribution factors and available margins on critical network elements;
10. ‘contingency’ means the identified and possible or already occurred fault of an element, including not only the transmission system elements, but also significant grid users and distribution network elements if relevant for the transmission system operational security;
11. ‘coordinated capacity calculator’ means the entity or entities with the task of calculating transmission capacity, at regional level or above;
12. ‘generation shift key’ means a method of translating a net position change of a given bidding zone into estimated specific injection increases or decreases in the common grid model;
13. ‘remedial action’ means any measure applied by a TSO or several TSOs, manually or automatically, in order to maintain operational security;
14. ‘reliability margin’ means the reduction of cross-zonal capacity to cover the uncertainties within capacity calculation;”
Furthermore, each proposal shall meet the general objectives of the CACM Regulation as outlined in Article 3:
“This Regulation aims at:
(a) promoting effective competition in the generation, trading and supply of electricity;
(b) ensuring optimal use of the transmission infrastructure;
(c) ensuring operational security;
(d) optimising the calculation and allocation of cross-zonal capacity;
(e) ensuring fair and non-discriminatory treatment of TSOs, NEMOs, the Agency, regulatory authorities and market participants;
(f) ensuring and enhancing the transparency and reliability of information;
(g) contributing to the efficient long-term operation and development of the electricity transmission system and electricity sector in the Union;
(h) respecting the need for a fair and orderly market and fair and orderly price formation;
(i) creating a level playing field for NEMOs;
(j) providing non-discriminatory access to cross-zonal capacity.”
As a general point, all methodologies and proposals developed under the CACM Regulation should align with the objectives of the CACM Regulation as set out in Article 3. More specifically, Article 9(9) of the CACM Regulation requires that:
“The proposal for terms and conditions or methodologies shall include a proposed timescale for their implementation and a description of their expected impact on the objectives of this Regulation.”
Article 14 of the CACM Regulation sets requirements for market timeframes to be followed in drafting the CCM:
“1. All TSOs shall calculate cross-zonal capacity for at least the following time-frames:
(a) day-ahead, for the day-ahead market;
(b) intraday, for the intraday market.
2. For the day-ahead market time-frame, individual values for cross-zonal capacity for each day- ahead market time unit shall be calculated. For the intraday market time-frame, individual values for cross-zonal capacity for each remaining intraday market time unit shall be calculated.
3. For the day-ahead market time-frame, the capacity calculation shall be based on the latest available information. The information update for the day-ahead market time-frame shall not start before 15:00 market time two days before the day of delivery.
4. All TSOs in each capacity calculation region shall ensure that cross-zonal capacity is
recalculated within the intraday market time-frame based on the latest available information.
The frequency of this recalculation shall take into consideration efficiency and operational security.”
Article 20 of the CACM Regulation sets deadlines for the CCM proposal and defines several specific requirements that the CCM Proposal for CCR Nordic should take into account:
“1. For the day-ahead market time-frame and intraday market time-frame the approach used in the common capacity calculation methodologies shall be a flow-based approach, except where the requirement under paragraph 7 is met.
2. No later than 10 months after the approval of the proposal for a capacity calculation region in accordance with Article 15(1), all TSOs in each capacity calculation region shall submit a proposal for a common coordinated capacity calculation methodology within the respective region. The proposal shall be subject to consultation in accordance with Article 12. […]
7. TSOs may jointly request the competent regulatory authorities to apply the coordinated net transmission capacity approach in regions and bidding zone borders other than those referred to in paragraphs 2 to 4, if the TSOs concerned are able to demonstrate that the application of the capacity calculation methodology using the flow-based approach would not yet be more efficient compared to the coordinated net transmission capacity approach and assuming the same level of operational security in the concerned region.
8. To enable market participants to adapt to any change in the capacity calculation approach, the TSOs concerned shall test the new approach alongside the existing approach and involve market participants for at least six months before implementing a proposal for changing their capacity calculation approach.
9. The TSOs of each capacity calculation region applying the flow-based approach shall establish and make available a tool which enables market participants to evaluate the interaction between cross-zonal capacities and cross-zonal exchanges between bidding zones.”
The FB approach shall be the approach used in the common CCM for the day-ahead and intraday market timeframes, in CCR regions specified in Article 20(2), Article 20(3) and Article 20(4) of the CACM
Regulation. For the Nordic CCR, the CACM Regulation (Article 20(1)) gives the possibility, instead of the FB approach, to apply the CNTC approach if the Nordic TSOs are able to demonstrate that the application of the CCM using the FB approach would not yet be more efficient compared to the CNTC approach and given the same level of operational security in the Nordic CCR. Here the efficiency should be defined in the context of the capacity allocation and operational security. Thus for the day-ahead market
timeframe, a more efficient approach is the one, which maximizes the social welfare, i.e. the total market value of the day-ahead implicit auctions, and/or increases operational security. Social welfare is computed as the sum of the consumer surplus, the producer surplus, and the congestion income.
Article 21 of the CACM Regulation defines the minimum content for the CCM proposal, including methodologies for the calculation of the inputs to the capacity calculation, a detailed description of the capacity calculation approach, and a methodology for cross-zonal capacity. Besides this, Article 21 requests to define the frequency to reassess capacity for the intraday capacity calculation timeframe, a fallback procedure, and a future harmonization of inputs and methodology across CCRs:
“1. The proposal for a common capacity calculation methodology for a capacity calculation region determined in accordance with Article 20(2) shall include at least the following items for each capacity calculation time-frame:
(a) methodologies for the calculation of the inputs to capacity calculation, which shall include the following parameters:
(i) a methodology for determining the reliability margin in accordance with Article 22;
(ii) the methodologies for determining operational security limits, contingencies relevant to capacity calculation and allocation constraints that may be applied in accordance with Article 23;
(iii) the methodology for determining the generation shift keys in accordance with Article 24;
(iv) the methodology for determining remedial actions to be considered in capacity calculation in accordance with Article 25.
(b) a detailed description of the capacity calculation approach which shall include the following:
(i) a mathematical description of the applied capacity calculation approach with different capacity calculation inputs;
(ii) rules for avoiding undue discrimination between internal and cross-zonal exchanges to ensure compliance with point 1.7 of Annex I to Regulation (EC) No 714/2009;
(iii) rules for taking into account, where appropriate, previously allocated cross-zonal capacity;
(iv) rules on the adjustment of power flows on critical network elements or of cross-zonal capacity due to remedial actions in accordance with Article 25;
(v) for the flow-based approach, a mathematical description of the calculation of power transfer distribution factors and of the calculation of available margins on critical network elements;
(vi) for the coordinated net transmission capacity approach, the rules for calculating cross-zonal capacity, including the rules for efficiently sharing the power flow capabilities of critical network elements among different bidding zone borders;
(vii) where the power flows on critical network elements are influenced by cross-zonal power exchanges in different capacity calculation regions, the rules for sharing the power flow capabilities of critical network elements among different capacity calculation
regions in order to accommodate these flows.
(c) a methodology for the validation of cross-zonal capacity in accordance with Article 26.
2. For the intraday capacity calculation time-frame, the capacity calculation methodology shall also state the frequency at which capacity will be reassessed in accordance with Article 14(4), giving reasons for the chosen frequency.
3. The capacity calculation methodology shall include a fallback procedure for the case where the initial capacity calculation does not lead to any results.
4. All TSOs in each capacity calculation region shall, as far as possible, use harmonised capacity calculation inputs. By 31 December 2020, all regions shall use a harmonised capacity calculation methodology which shall in particular provide for a harmonised capacity calculation
methodology for the flow-based and for the coordinated net transmission capacity approach. The harmonisation of capacity calculation methodology shall be subject to an efficiency assessment concerning the harmonisation of the flow-based methodologies and the coordinated net transmission capacity methodologies that provide for the same level of operational security. All TSOs shall submit the assessment with a proposal for the transition towards a harmonised capacity calculation methodology to all regulatory authorities within 12 months after at least two capacity calculation regions have implemented common capacity calculation methodology in accordance with Article 20(5).”
According to Article 21 of the CACM Regulation, the proposal shall define methodologies for the calculation of the inputs to the capacity calculation, a detailed description of the capacity calculation approach, and a methodology for the validation of cross-zonal capacity. Cross-zonal is understood to refer to cross bidding zone borders, regardless of whether these borders are within a Member State or between Member States.
The requirement under Article 21(1) (b) (ii), to set rules to avoid undue discrimination between internal and cross-zonal exchanges, implies that unless for reasons of either operational security and economic efficiency, neither internal nor cross-zonal exchanges can be given priority access to transmission capacity within bidding zones. However, due to the zonal approach in the congestion management, it is not possible to expose internal trades to prices competition. This implies that internal trades might be prioritized due to the existence of internal grid limitations when the above-mentioned reasons on operational security and economic efficiency apply. If so, the requests for internal exchanges will get priority access to the scarce network capacity, whereas the requests for cross-zonal exchanges can access only that part of the scarce network capacity that is not already used by internal exchanges. On occasions where the above-mentioned reasons do not apply, limitations on internal network elements will not be considered in the cross-zonal capacity calculation.
Generally, all cross-zonal capacities in CCR Nordic are allocated in day-ahead and intraday market couplings; only on one border PTRs for a forward timeframe are allocated. This implies that for the day- ahead timeframe there are no previously allocated cross-zonal capacities, except for one bidding zone border, where the effect of nominated PTRs to the cross-zonal capacity has to be taken into account when providing cross-zonal capacity to the allocation in the day-ahead timeframe. For the intraday timeframe there are allocated cross-zonal capacities from the day-ahead timeframe and these allocated capacities have to be taken into account when providing cross-zonal capacity to the allocation in the intraday timeframe. Besides this, if there are capacity reservations in the long-term, day-ahead, and
intraday timeframe, such as reservations for FRR, these reservations have to be taken into account in the relevant timeframes to define previously allocated cross-zonal capacities. Rules for taking into account previously allocated cross-zonal capacity have to be defined for all bidding zone borders in the intraday and day-ahead timeframe.
Article 21(1)(b)(iv) requires to set rules on the adjustment of power flows on critical network elements (CNEs) or of cross-zonal capacity due to remedial actions (RAs) in accordance with Article 25. Article 25 requires that at least RAs without cost – such as change of grid topology or other measures under TSOs’
control – have to be taken into account in the capacity calculation. The effects of the application of these RAs, and application of RAs with costs agreed with market participants – such as countertrading and redispatching – shall be taken into account. For the FB approach, this means adjustments of the remaining available margins (RAMs) of the CNEs, and for the CNTC approach it boils down to an adjustment of the cross-zonal capacity.
Article 21(1)(b)(vi) requires to set the rules for calculating cross-zonal capacity including the rules for efficiently sharing the power flow capabilities of CNEs among the different bidding zones for the CNTC approach. The CNTC approach may be applied in CCRs, where cross-zonal capacity between bidding zones is less interdependent and each bidding zone border can be treated separately during the capacity calculation. However, if interdependency exists, the rules to model this interdependency have to be defined and then applied in the CNTC approach. The FB approach should be used as a primary approach for day-ahead and intraday market timeframe, where cross-zonal capacity between bidding zones is highly interdependent.
Article 21(1)(b)(vii) requires, in cases where the power flows on CNEs are influenced by cross-zonal power exchanges in different CCRs, to set the rules for sharing the power flow capabilities of CNEs among different CCRs in order to accommodate these flows. Generally, the CCRs have been configured to minimize the influence of different CCRs to CNEs in a CCR. This influence can occur especially in CCRs, which reside at the same synchronous area requiring cooperation between neighboring coordinated capacity calculators (CCCs) regarding exchanging and confirming information on interdependency with the relevant regional CCCs and defining together rules to take these interdependencies into account.
Article 21(2) requires that the CCM shall also state the frequency at which capacity will be reassessed in accordance with Article 14(4), giving reasons for the chosen frequency. Article 14(4) requires that all TSOs in each CCR shall ensure that cross-zonal capacity is recalculated within the intraday market timeframe based on the latest available information. In accordance with Article 14(4) the frequency of this recalculation shall take into consideration efficiency and operational security. The frequency of reassessment depends on updates made to the CGM and regional/national updates during the calculation process. Currently it is foreseen that there will be one dedicated European CGM model for each market time unit of the intraday timeframe. However, it is possible to make capacity reassessment based on national/regional updates to the CGMs and to increase the frequency of national/regional
capacity reassessments during the intraday market timeframe to ensure operational security while still having an efficient calculation process.
Article 21(3) requires that the CCM shall include a fallback procedure for the case when the initial capacity calculation does not lead to any results. This fallback procedure shall be developed for both the day-ahead and intraday market timeframes.
Article 22 of the CACM Regulation sets requirements to the reliability margin (RM) methodology, which is part of the CCM in accordance with Article 21(1)(a)(i):
“1. The proposal for a common capacity calculation methodology shall include a methodology to determine the reliability margin. The methodology to determine the reliability margin shall consist of two steps. First, the relevant TSOs shall estimate the probability distribution of
deviations between the expected power flows at the time of the capacity calculation and realised power flows in real time. Second, the reliability margin shall be calculated by deriving a value from the probability distribution.
2. The methodology to determine the reliability margin shall set out the principles for calculating the probability distribution of the deviations between the expected power flows at the time of the capacity calculation and realised power flows in real time, and specify the uncertainties to be taken into account in the calculation. To determine those uncertainties, the methodology shall in particular take into account:
(a) unintended deviations of physical electricity flows within a market time unit caused by the adjustment of electricity flows within and between control areas, to maintain a constant frequency;
(b) uncertainties which could affect capacity calculation and which could occur between the capacity calculation time-frame and real time, for the market time unit being considered.
3. In the methodology to determine the reliability margin, TSOs shall also set out common harmonised principles for deriving the reliability margin from the probability distribution.
4. On the basis of the methodology adopted in accordance with paragraph 1, TSOs shall
determine the reliability margin respecting the operational security limits and taking into account uncertainties between the capacity calculation time-frame and real time, and the remedial actions available after capacity calculation.
5. For each capacity calculation time-frame, the TSOs concerned shall determine the reliability margin for critical network elements, where the flow-based approach is applied, and for cross- zonal capacity, where the coordinated net transmission capacity approach is applied.”
Article 23 of the CACM Regulation sets requirements to the methodologies for operational security limits and contingencies and allocation constraints, which is part of the CCM in accordance with Article 21(1)(a)(ii):
“1. Each TSO shall respect the operational security limits and contingencies used in operational security analysis.
2. If the operational security limits and contingencies used in capacity calculation are not the same as those used in operational security analysis, TSOs shall describe in the proposal for the common capacity calculation methodology the particular method and criteria they have used to determine the operational security limits and contingencies used for capacity calculation.
3. If TSOs apply allocation constraints, they can only be determined using:
(a) constraints that are needed to maintain the transmission system within operational security limits and that cannot be transformed efficiently into maximum flows on critical network elements; or
(b) constraints intended to increase the economic surplus for single day-ahead or intraday coupling.”
Operational security limits mean, in accordance with Article 2(7), the acceptable operating boundaries for secure grid operation such as thermal limits, voltage limits, short-circuit current limits, frequency and dynamic stability limits. The list consists of the limits applied currently in the operational security
analysis. Operational security limits are the same for CGM scenarios (e.g. minimum and maximum voltage and frequency limits, damping limits for voltage or rotor angle stability) and may be updated when ambient conditions (e.g. temperatures) or voltage/current ranges of devices connected to the grid (e.g. maximum currents, lowest voltages) change. Furthermore, guiding principles are needed to ensure that all TSOs in the CCR Nordic are using the same definitions when submitting operational security limits to the CCC. TSOs have to be transparent on the application of these operational security limits. These operational security limits will be applied to define maximum flows across CNEs or bidding zone borders.
Contingency means, in accordance with Article 2(10), the identified and possible or already occurred fault of an element, including not only the transmission system elements, but also significant grid users and distribution network elements if relevant for the transmission system operational security.
The contingencies shall be the same as those for the security analysis in accordance with the SO Regulation, generally meeting all N-1 situations, and thus there is no need to describe the particular method and criteria to be used to determine contingencies used in the capacity calculation.
Allocation constraints mean, in accordance with Article 2(6), the constraints to be respected during the capacity allocation to maintain the transmission system within operational security limits and that have not been translated into cross-zonal capacity or that are needed to increase the efficiency of capacity allocation.
TSOs may use these constraints in two occasions and they can be only used in the allocation phase, not in the capacity calculation phase. First usage of the allocation constraints is to maintain operational security in case where such constraints cannot be efficiently transformed to maximum flows on critical network elements. These constraints can be e.g. minimum production capacity or reserves within a bidding zone, or ramping constraints between market time units. Second usage of the allocation constraints is to increase economic surplus for single day-ahead or intraday coupling. These constraints can be e.g. losses on HVDC interconnections.
Article 24 of the CACM Regulation sets requirements to the generation shift key (GSK) methodology, which is part of the CCM in accordance with Article 21(1)(a)(iii):
“1. The proposal for a common capacity calculation methodology shall include a proposal for a methodology to determine a common generation shift key for each bidding zone and scenario developed in accordance with Article 18.
2. The generation shift keys shall represent the best forecast of the relation of a change in the net position of a bidding zone to a specific change of generation or load in the common grid model.
That forecast shall notably take into account the information from the generation and load data provision methodology.”
GSK means, in accordance with Article 2(12), a method of translating a net position change of a given bidding zone into estimated specific injection increases or decreases in the CGM.
A common GSK shall be developed for each bidding zone and scenario. GSKs will be used to translate a change in net positions into specific nodal injections in the CGM to reflect best the forecasted change in generation or load within a bidding zone.
Article 25 of the CACM Regulation sets requirements to the methodology for RAs in capacity calculation, which is part of the CCM in accordance with Article 21(1)(a)(iv):
“1. Each TSO within each capacity calculation region shall individually define the available remedial actions to be taken into account in capacity calculation to meet the objectives of this Regulation.
2. Each TSO within each capacity calculation region shall coordinate with the other TSOs in that region the use of remedial actions to be taken into account in capacity calculation and their actual application in real time operation.
3. To enable remedial actions to be taken into account in capacity calculation, all TSOs in each capacity calculation region shall agree on the use of remedial actions that require the action of more than one TSO.
4. Each TSO shall ensure that remedial actions are taken into account in capacity calculation under the condition that the available remedial actions remaining after calculation, taken
together with the reliability margin referred to in Article 22, are sufficient to ensure operational security.
5. Each TSO shall take into account remedial actions without costs in capacity calculation.
6. Each TSO shall ensure that the remedial actions to be taken into account in capacity calculation are the same for all capacity calculation time-frames, taking into account their technical availabilities for each capacity calculation time-frame.”
RA means, in accordance with Article 2(13), any measure applied by a TSO or several TSOs, manually or automatically, in order to maintain operational security. RAs can be applied also in the capacity
calculation phase, where each TSO shall individually define the available RAs to be taken into account to meet the objectives under Article 3 of the CACM Regulation.
RAs without costs (such as grid topology change, phase shifter actions, system protection schemes5) shall be taken into account in the capacity calculation and costly RA will be taking into account if available, but only if the EU-wide economic efficiency of applying the costly RA compared to the option of limiting cross border exchanges can be demonstrated
Each TSO has to coordinate the use of RAs, to be taken into account in the capacity calculation, with other TSOs in the same CCR. RAs can be taken into account in the capacity calculation on the condition that the RAs available after the capacity calculation are sufficient to ensure operational security.
The RAs to be taken into account in capacity calculation shall be the same for all capacity calculation timeframes (from day-ahead to intraday timeframe), taking into account their technical availabilities for each capacity calculation timeframe.
Article 26 of the CACM Regulation sets requirements to a cross-zonal capacity validation methodology, which is part of the CCM in accordance with Article 21(1)(c):
“1. Each TSO shall validate and have the right to correct cross-zonal capacity relevant to the TSO's bidding zone borders or critical network elements provided by the coordinated capacity calculators in accordance with Articles 27 to 31.
2. Where a coordinated net transmission capacity approach is applied, all TSOs in the capacity calculation region shall include in the capacity calculation methodology referred to in Article 21 a rule for splitting the correction of cross-zonal capacity between the different bidding zone
borders.
3. Each TSO may reduce cross-zonal capacity during the validation of cross-zonal capacity referred to in paragraph 1 for reasons of operational security.
5Please note that system protection schemes might bring a cost when they are activated.
4. Each coordinated capacity calculator shall coordinate with the neighbouring coordinated capacity calculators during capacity calculation and validation.
5. Each coordinated capacity calculator shall, every three months, report all reductions made during the validation of cross-zonal capacity in accordance with paragraph 3 to all regulatory authorities of the capacity calculation region. This report shall include the location and amount of any reduction in cross-zonal capacity and shall give reasons for the reductions.
6. All the regulatory authorities of the capacity calculation region shall decide whether to publish all or part of the report referred to in paragraph 5.”
3 Introduction to FB capacity calculation methodology
The purpose of this chapter is to introduce the FB approach and highlight the differences compared to CNTC. The introduction will be relatively high level and aims at giving the overall understanding of FB approach and the motivation behind using the approach before more technical descriptions in the subsequent chapters.
Motivation behind introducing FB approach in the CCR Nordic
3.1In the electricity markets, the transmission grid constrains how much electricity can be transferred between any two points in the grid. Even if these limitations can be removed by new investments, investments in transmission capacity is capital intensive and has a diminishing marginal value. Thus unlimited expansion of the transmission grid is unrealistic due to economics. This limiting nature of the transmission grid creates a need to have a methodology to optimize the utilization of the transmission grid according to the demand for electric power, and the complex physical limits of the grid must be expressed in a simplified manner to be communicated and understood by the electricity market.
Renewable energy is also a factor that creates a need for focusing of optimizing the scarce transmission capacity. When renewable energy is integrated into an electricity system, the location of the renewable energy can often be concentrated due to advantageous geographical areas, and weather patterns like wind that moves across geographical areas, which creates large differences in production volumes. To accommodate the difference in production there is a need to transport large quantities of electrical power across geographical areas. An example of this could be a windy day in the south west of Scandinavia. In such situations, Denmark has excessive wind production at a low marginal cost. This excess power could be moved to Sweden and Norway at higher prices, thus optimizing the value of the renewable production. In turn on a day with low wind, Denmark can benefit from the hydro production in Norway. To illustrate the current Nordic power system, see Figure 2.
Figure 2 Map showing the Nordic power system (ENTSO-E, 2016). The transmission grid is needed to transport electric power from sites of generation to sites of consumption, but this grid has a limited capacity to transmit electric power.
In reality, a power system is a non-linear system with endless complexities. However, the algorithms used to calculate the electricity prices and volumes are simplified in order to meet operational
requirements. One of the simplifications is the representation of transmission grid capacities. In the price calculation algorithm, transmission capacities are represented as linear constraints where all constraints are modeled as fixed numbers. This gives the TSOs the task of supplying accurate information to the algorithm while respecting the constraints on linearity. Another of the simplifications is the
representation of bidding zones. In reality, a power system consists of nodes that are geographically be located. In the simplification a large set of nodes are clustered together in a bidding zone, and the transmission grid is represented by bidding zone borders, thus congestions occurs on these borders in the electricity market, but in reality these congestions could be caused by any internal node and/or line not only at the bidding zone borders.
The better the representation of the transmission grid is in the electricity market, the more accurate the TSO can feed physical constraints into the price calculation algorithm. The motivation behind introducing the FB approach, is that the FB approach has the potential to better take into account the physical flow and constraints compared to the current NTC method. A better representation gives a better chance of optimizing the utilization of the scarce transmission capacity, which should lead to more accurate price signals and increased social economic welfare.
Over the last ten years several new HVDC interconnections have been commissioned across Europe, and in the coming years we expect further development of the transmission grid in terms of
interconnections. Europe has also seen a sharp increase in the amount of renewable energy in the power system, and in order to fulfill emission reduction targets it is expected to increase further. This
development has increased the interdependency as well as the complexity of the power system, and has increased volatility in production patterns. This has made it difficult to decide how to share transmission capacity for different bidding zone borders within the current NTC approach.
According to the CACM, the future capacity calculation methodology for the European day-ahead and intraday markets may be either FB or a CNTC approach. However the CACM Regulation requires that
“TSOs may jointly request the competent regulatory authorities to apply the coordinated net transmission capacity approach if the TSOs concerned are able to demonstrate that the application of the capacity calculation methodology using the flow based approach would not yet be more efficient compared to the net transmission capacity approach and assuming the same level of operational security in the concerned region”. It is not assumed that the CNTC method is as efficient as FB approach in the CCR Nordic. This is due to the presence of high levels of renewables and the relatively large number of bidding zones and interconnections between these bidding zones. This assumption effectively means that the CCR Nordic has to develop FB approach as the capacity calculation methodology in the future.
To illustrate the complexity and challenges within the CCR Nordic, the interdependencies in the power grid are illustrated in Figure 3 Commercial flows vs physical flows in the Nordic grid. Power is injected in bidding zone NO3 and consumed in bidding zone SE2. The figure illustrates a situation with a generation
increase in bidding zone NO3 that is “consumed“ in bidding zone SE2 (yellow arrows). With the current NTC approach, this would generate a commercial trade between the two areas, as illustrated by the orange arrow.
Figure 3 Commercial flows vs physical flows in the Nordic grid. Power is injected in bidding zone NO3 and consumed in bidding zone SE2
In reality, the physical flow from this trade would fan out in the transmission grid and follow the blue arrows in Figure 3. The largest flows are in the central area, but many tiny flows arise all over the power system as a consequence of the trade. All smaller transit flows are disregarded by the market, but in reality these flows are using available transmission capacity in other parts of the power system. This is called an external effect, and it has a negative impact on other market participants, who will face less transmission capacity due to this trade.
In the current NTC based capacity allocation method, the TSOs take the transit flows into account when calculating the amount of transmission capacity to be allocated on each bidding zone border in the day- ahead and intraday markets. If the forecasted trade is not realized, then the reductions due to transit flows are useless. This makes the accuracy of the TSO forecasts very important for the efficiency of the system, as these forecasts affect the capacity calculation and its outcome.
NO1
NO2 NO3
NO4
NO5
SE1
SE2
SE3
SE4
FI
DK1 DK2
In the FB approach, the transit flows are internalized into the market. This means that all commercial exchanges have to compete for the transmission capacity, including transit flows. This internalization should in theory make the FB approach more efficient at managing congestions of the transmission grid.
Description of FB approach
3.2In order to understand the FB approach this section will to some extent compare the differences of FB and (C)NTC approaches, this is to help the reader understand the changes in the capacity calculation once the approach is switched from the current NTC approach to FB approach. It is important to note that NTC is not CACM compliant, which means that some changes have to be made even if FB approach didn’t have additional benefits compared to CNTC approach, although changes are in this case smaller and not affecting the output format of the results to market participants.
The Nordic day-ahead electricity market is part of the larger European electricity market. Market participants submit orders to the Nominated Electricity Market Operator6 (NEMO). The NEMO forwards the orders to the joint European market coupling function (MCO) where the price coupling algorithm, Euphemia, solves an European-wide equilibrium, based on explicit economic welfare optimization. The organization of the intraday market is slightly different from the day-ahead market. In the intraday market, market participants submit orders to the NEMO, who forwards the orders to the intraday market platform. However, there is no explicit welfare optimization, rather a continuous matching of bids taking into account the transmission grid constraints. The process looks different from the day- ahead process, but in essence the outcome will be an implicit optimization of economic welfare taking into account the transmission grid constraints.
The market results of the intraday and day-ahead allocation process have to respect the physical limitations of the transmission grid. For this purpose, the TSOs currently provide transmission capacities between bidding zones to the market. These transmission capacities act as constraints in the day-ahead and intraday market coupling algorithms.
In the FB approach the market coupling algorithm receives constraints in the format of power transfer distribution factors (PTDF) and remaining available margins (RAM), rather than transmission capacity between bidding zone borders. Essentially RAM can be understood as the transmission capacity given to the market. To understand what PTDFs are, it is useful to illustrate the difference between FB and CNTC approaches using a simple three bidding zone grid shown in Figure 4.
6There may be more than one NEMO in an area, but this does not change the procedure, the market participant just chooses one of the approved NEMOs.
Figure 4 Transmission grid with three bidding zones.
In this example there are no internal constraints within the bidding zones, complex grid limitations or outages being considered. This means that the only limiting grid elements are the connecting
transmission lines between the bidding zones7. All lines have a thermal capacity of 1000 MW and equal impedance (equal “electrical distance”). This thermal capacity of 1000 MW is referred to as RAM. RAM is the factor limiting the sum of power flows coming from all bidding zones that may flow on a particular connecting line at one point of time. Bidding zone C is a consumption bidding zone while bidding zones A and B are generation zones. At the time of capacity calculation (D-1)8, the TSO does not know the final net position in the bidding zones, only the physical properties of the transmission grid. Due to the transmission grid topology, one MW produced in bidding zone A will induce a flow of 2/3 MW on the connecting line AC, 1/3 MW on the connecting line AB and 1/3 MW on the connecting line BC. The same holds true for generation in bidding zone B of which -1/3 appears on AB, 1/3 on AC and 2/3 on BC. These factors are known as PTDFs. PTDFs are parameters, which show how much power is flowing on a
particular transmission grid element when injecting one additional MW in a particular bidding zone.
In this example bidding zone C is a “slack node”, this means that all power injected in bidding zones A and B is (mathematically) absorbed in bidding zone C. The same holds true for bidding zone C itself, all power injected in bidding zone C is absorbed in C. The flow influence of each bidding zone to each connecting line defines the PTDF matrix in Table 1.
7 This is a simplification – in reality constraints in the form of CNEs can be anywhere inside the bidding zone.
8 The capacity calculation starts at D-2. Final values are provided to the market at D-1
Table 1 PTDF matrix of the transmission grid in Figure 4
The main difference between FB and CNTC approach is that in the CNTC approach the parameters above (PTDFs and RAMs) would not be provided to the NEMO, which means that only FB approach has a built- in representation of the actual power flows. In CNTC approach an example could be that it is assumed that one MW produced in bidding zone A flows with an equal distribution between connecting lines AC and AB/BC. This would allow the market coupling algorithm to carry 2000 MW from bidding zone A to bidding zone C, as this would create a flow of 1000 MW on connecting line AC and 1000 MW on connecting lines AB/BC. In reality this would create an overload as the PTDFs show that 2000 MW injected in bidding zone A would create a physical flow of 2/3*2000 = 1333 MW on connecting line AC which is in breach of the thermal limits. In this case a possible way to solve the issue in the CNTC
approach is to limit the exchange capacity to 750 MW on connecting lines AC and AB/BC, other solutions are also feasible e.g. setting connecting line AC to 1500 MW and connecting lines AB/BC to 0 MW.
The FB approach will yield a larger set of possibilities, as this method will take the PTDF matrix into account. An example of this would be a situation where the following injection is made A=2000, B=-1000 and C=-1000, this would induce a flow of 2000*1/3-1000*(-) 1/3-1000*0=1000 on connecting line AB.
The solution domains for CNTC and FB approaches are illustrated in Figure 5.
Figure 5 Solution domains for CNTC and FB approaches
As it is shown in Figure 5, all CNTC solutions are contained in the FB solution domain. This means that the FB approach has at least the same amount of possible solutions, and theoretically more. All points on the FB boundaries reflect transmission capacity limits in the grid that will induce price differences in all nodes, without implying that all transmission lines are congested simultaneously. This market solution is, however, not possible in the CNTC approach due to the fact that in CNTC allocation the real physical flows (the PTDF matrix) are not known between bidding zones.
It is important to note some simplifications of the FB approach. As mentioned earlier in this chapter multiple nodes are combined into one bidding zone. In the pure version of FB approach, called nodal pricing, each node would constitute its own bidding zone having its own price. In the FB approach applied in Europe, nodes are combined into bidding zones. This is done to satisfy the practicality in keeping the number of bidding zones relatively low – in the Nordic countries there are altogether 12 bidding zones. A new issue arises when combining nodes into bidding zones; how to secure a balance between generation and consumption in each node if the price – in contrast to nodal pricing – cannot be used as the balancing mechanism?
This issue is solved using GSKs. The GSK is a value which is used in the translation from node-to-CNE PTDFs to zone-to-CNE PTDFs. The relation is formally expressed as:
∑ , and ∑ (1)
= Sensitivity of CNE "j" to injection of 1MW in bidding area "A"
= Sensitivity of CNE"j" to injection of 1MW in bidding area "α"
= Weight of node "α" on the PTDFs of bidding zone "A"
The FB approach makes use of GSKs to describe how the net position of one node changes with the net position of the bidding zone it is a part of, hence the GSKs for a particular bidding zone shall sum to 1.
There is an infinite amount of different ways, or strategies, for how to generate GSKs, and none of the GSK strategies are theoretically right or wrong. However, it is important to understand that the choice of GSK strategy will influence the market. A poor choice might result in a large adverse market influence, thus making GSKs and the GSK strategy one of the biggest sources of inaccuracies in the calculation of the FB parameters (PTDFs and RAMs). The perfect strategy would mimic the market outcome of nodal pricing, but this is not possible as this would require perfect foresight of the TSO, which might not be possible in current liberalized electricity markets.
The GSK parameters (or GSK factors) are a linear representation of a complex non-linear process, and the simplest form of a GSK strategy is flat participation. This means that each node inside a bidding area will have an equal impact on a particular zone-to-CNE PTDF for that bidding zone, which theoretically might require more generation from a node than the maximum installed generation capacity at that node.
However, the strength of GSK strategies is that the design is not limited to using the same strategy for all bidding zones. It is possible that the optimal strategy for each bidding zone and time stamp might differ.
Luckily, it is possible in the FB approach (or in CNTC approach) to take into account differences in optimal GSK strategies, but identifying the optimal GSK strategy for each bidding zone and each time stamp is demanding. It is, however, a requirement in the CACM Regulation, that the rules guiding GSK strategies are harmonized across TSOs as they have such a large impact on capacity allocation.
In the initial version of the Nordic FB approach, the flat GSK strategy has been applied. However, outcomes from other GSK strategies will be monitored to provide an empirical basis for further development of the Nordic FB approach.
Another imperfection of the FB approach is loop flows. Loop flows arise when a commercial trade within a bidding zone creates flows that run through other bidding zones to end back in the original bidding zone. Loop flows do not exist in a nodal pricing system; in the FB approach they arise as a consequence of keeping the existing bidding zone structure. In the ACER recommendations “On the common capacity calculation and re-dispatching and countertrading cost sharing methodologies” it is specified as a general principle that cross zonal capacities should not be lowered as a consequence of loop flows. In the short run, loop flows have to be handled by RAs such as counter trading and redispatching. In the medium term, loop flows should be handled by reconfiguring bidding zones, and in the long run they should be handled by investments in the transmission grid.
The Nordic power system is far more complex than illustrated in the simple three bidding zone transmission grid in Figure 4. Thus, the complexity of assigning exchange capacity is also far more
complex. This is illustrated in Figure 6, with the real bidding zones and connections in the Nordic system.
Figure 6 The Nordic power system and its connections to neighboring power systems.
This figure gives a schematic overview of the Nordic power system. AC interconnections are illustrated by red arrows and DC interconnections by black arrows. The maximum power exchange values for each interconnection is shown in black numbers, together with the provided transmission capacities for Jan 6'th 2017 at hour 10:00 – 11:00 in red numbers. The differences are due to
both loop flow considerations and the outage situation on the relevant day. The Nordic bidding zones DK1, DK2, SE4 and FI are radially connected to the rest of the Nordic AC system, and thus not influenced by loop flows. The rest of the Nordic power system is
interdependent and influenced by loop flows.
There are currently twelve bidding zones within the Nordic countries and five connected external bidding zones in the CCRs of Core, Hansa, and the Baltic. Altogether, there are 26 connections between bidding zones within the Nordic countries and between the Nordic countries and the external areas in other CCRs. For each interconnection, there is one transmission capacity in each direction for each hour of the
day, and thus, the Nordic TSOs provides 1248 hourly transmission capacities per day, and 455 520 hourly transmission capacities per year.
4 Motivation for the articles in the CCM proposal
This chapter presents explanations of the proposed CCM articles. The aim of the chapter is to provide for a motivation for the content of each of the articles and the thinking that lies behind.
Article 2: Definitions and interpretation
4.1"Advanced Hybrid Coupling"
The term "hybrid coupling" refers to the integration of the two capacity calculation methodologies, the CNTC and the FB approach.
Power flows on HVDC interconnections are by nature fully manageable, and a radial AC transmission grid has no meshed structure for the power to fan out. Thus, in a pure HVDC network, or in a radial AC transmission grid, both the CNTC and FB perception of the power flows corresponds fully to the real physics of the power system. However, in a meshed AC network, the FB (or nodal) approach is the only one of the two which is able to manage real physical power flows.
In the Nordic countries, all interconnections to adjacent synchronous areas are either HVDC or radial interconnections. These parts of the Nordic transmission grid area by definition a physical embodiment of CNTC, and it doesn't make sense to implement an FB approach on these parts of the transmission grid (an FB approach would anyhow behave as a CNTC approach). With this realization in mind, the Nordic CCM have to apply a hybrid coupling to integrate the HVDC and radial AC interconnections in the meshed AC grid.
The "hybrid coupling" might be either the standard hybrid coupling (SHC) or the advanced hybrid
coupling (AHC). Before entering into the explanation of SHC and AHC, it is important to bear in mind that when the power flows from an HVDC or a radial AC interconnection enters the meshed AC transmission grid, the power flow will fan out in the AC transmission grid and use the scarce transmission capacity like all other power flows in the transmission grid.
The distinction between SHC and AHC is the difference in how power flows coming from a radial AC or HVDC interconnection are managed by the market coupling in the meshed AC transmission grid. On a high level, the SHC is granting priority access in the meshed AC transmission grid for power flows coming from a radial AC or a HVDC interconnection, while in the AHC, these power flows are subjected to competition for transmission capacity with all other power flows in the transmission system.
In the rest of this chapter, the term HVDC interconnection means both radial AC and HVDC interconnections. Both SHC and AHC are based on CGMs. In SHC, an expected flow on the HVDC
interconnection is at first calculated for the base case net positions. In order to guarantee the estimated power flow on HVDC interconnection, the resulting power flows in the meshed AC grid must be granted priority access on the relevant grid limitations. This can be done by applying the nodal PTDF matrix on all limiting CNEs from the "access point node" of the relevant HVDC interconnection to calculate the
